Power utilities generate electrical power at remote plants and deliver electricity to residential, business or industrial customers via transmission networks and distribution grids. Power is first transmitted as high voltage transmissions from the remote power plants to geographically diverse substations. From the substations, the received power is sent using cables or “feeders” to local transformers that further reduce the voltage. The outputs of the transformers are connected to a local low voltage power distribution grid that can be tapped directly by the customers. The power distribution grids can be configured as either radial or networked systems. A radial distribution system includes a number of feeder circuits that extend radially from a substation. Each circuit serves customers within a particular area and the failure of a radial circuit cuts off electric service to the customers on that circuit. In a networked distribution system, service is provided through multiple transformers connected in parallel, as opposed to the radial system in which there is only one path for power to flow from the substation to a particular load. A networked distribution system provides multiple potential paths through which electricity can flow to a particular load.
By its nature, a networked distribution system can be more reliable than a radial distribution system. When a networked distribution system is properly designed and maintained, the loss of any single low or high voltage component does not usually cause an interruption in service or degradation of power quality. Nevertheless, large events, such as feeder outages, transmission and substation events do occur, along with less substantial, although still important problems, such as low voltage complaints and distribution feeder failures remain. When a feeder fails, its substation protection circuitry will isolate it from its power supply in the substation automatically and are called “Open Autos” or O/As. When an O/A occurs, the load that had been carried by the failed feeder must shift to adjacent feeders, further stressing them. O/As put networks, control centers, and field crews under considerable stress, especially during the summer, and cost millions of dollars in operations and maintenance expenses annually.
Providing reliable electric supply requires active or continuous “control room” management of the distribution system by utility operators. Real-time response to a disturbance or problem may, for example, require redirecting power flows for load balancing or sectionalizing as needed. The control room operators must constantly monitor the distribution system for potential problems that could lead to disturbances. Sensors may be used to monitor the electrical characteristics (e.g., voltage, current, frequency, harmonics, etc.) and the condition of critical components (e.g., transformers, feeders, secondary mains, and circuit breakers, etc.) in the distribution system. The sensor data may guide empirical tactics (e.g., load redistribution in summer heat waves) or strategies (e.g., scheduling network upgrades at times of low power demand in the winter), and provide indications of unique or peculiar component life expectancy based on observations of unique or peculiar loads.
Often information about an electrical grid is not presented in an integrated fashion, as it is contained in as many as 20 separate applications that may each require separate security details (e.g. separate applications each requiring a separate log-in and password). Once logged in, the operator must drill-down to navigate through the applications to obtain the information he or she needs to analyze the contingency and respond.
For example, following an open auto of network feeder, operators need to communicate and coordinate the collection of a variety of information. Field personnel may report a manhole fire, station personnel may report relay targets and regional control center personnel may be reviewing Power Quality (PQ) node data and still others may be reviewing the specific PQ (power quality) application, RTF (reactance to fault), i.e., frequency, impedance and amplitude data to determine the location of a cable fault.
Accordingly, there is a need in the art for an approach to decision support which overcomes the limitations of the prior art and allows an operator to accurately, and quickly, identify and respond to contingencies based on an integrated view of the electrical grid which he/she is controlling.